Method for measuring surface torque oscillation performance index

ABSTRACT

A system and method for drilling a wellbore with a drill rig by: rotating a drillstring and a drill bit with a drill rig drive system; applying a weight of the drillstring on the drill rig; measuring surface torque oscillations of the drill string via: determining a fundamental oscillation time period; select a time window based on the fundamental oscillation time period; collecting torque present value data of the drill string for the selected time window; determining an amplitude of torque oscillation from the collected torque present value data; determining a reference torque; and dividing the determined amplitude of torque oscillation by the determined reference torque to obtain a surface torque oscillation performance index, whereby the measurement of the surface torque oscillations of the drill string is a fractional value to indicate the magnitude and severity of surface torque fluctuations of the drilling string; and modifying a drilling parameter based on the surface torque oscillation performance index.

TECHNICAL FIELD

The present disclosure relates generally to the field of drilling wells.More particularly, the invention concerns measuring a surface torqueoscillation performance index for controlling drilling operations,starting/stopping stick slip mitigation controls, and performancecomparisons between drill rigs and stick slip mitigation controlalgorithms.

BACKGROUND

Top drive is a drilling rig equipment that is located above the rigfloor and moves vertically along the derrick. It is a rotationalmechanical device providing primarily the torque that is needed by thedrilling bit to drill through formations. Top drive is mostly controlledby an AC/DC variable frequency drive (VFD). The VFD calculates andreports the torque values to the rig control system.

High amplitude rotational oscillations of the drillstring are a commonproblem while drilling. They are generated by the combination of thetorque generated by the interaction of the bit with the hole-bottom andof the drillstring with the borehole walls, and the lack of damping ofthe rotational oscillations. One of the reasons that there is so littledamping is that the bit-rock interaction does not provide any damping,and indeed can amplify the oscillations.

As explained in SPE 18049, slip-stick motion of the bottom hole assemblycan be regarded as extreme, self-sustained oscillations of the lowesttorsional mode, called the pendulum mode. Such a motion is characterizedby finite time intervals during which the bit is non-rotating and thedrill pipe section is twisted by the rotary table or top drive. When thedrillstring torque reaches a certain level (determined by the staticfriction resistance of the bottom hole assembly), the bottom holeassembly breaks free and speeds up to more than twice the nominal speedbefore it slows down and again comes to a complete stop. It is obviousthat such motion represents a large cyclic stress in the drill pipe thatcan lead to fatigue problems. In addition, the high bit speed level inthe slip phase can induce severe axial and lateral vibrations in thebottom hole assembly which can be damaging to the connections. Finally,it is likely that drilling with slip-stick motion leads to excessive bitwear and also a reduction in the penetration rate. Frequency analysis ofthe driving torque associated with torsional drillstring vibrations, inparticular slip-stick oscillations, reveals that a large number oftorsional drillstring resonances. The sharpness of the curve at thedrillstring resonance frequencies suggest there is little damping oftorsional drillstring vibrations. Halsey, Kyllingstad, and Kylling,“Torque Feedback Used to Cure Slip-Stick Motion,” SPE 18049, 1988.

Stick slip generates torsional waves travelling from the bottom of thedrillstring back to the surface which are seen at the top drive torquereadings, which show oscillations in different degrees of magnitude. Fewprior art methods systematically establish a surface torque oscillationmeasure. US2016/0076354, incorporated herein in its entirety, disclosesa method for detecting stick-slip in a drill string by measuring thesurface torque values from at least one sensor over a selected timeperiod. The measured values are filtered using a band pass filter andthe frequency band of the filter is dynamically adjusted based on thedetermined bit depth. The minimum and maximum torque values are capturedfrom the filtered data and a difference is determined using these twovalues. The surface stick slip index (SSSI) is determined by dividingthe difference of the maximum and minimum torque values by a movingaverage torque (times 2) over a constant selected time period.

Potential concerns regarding this method of determining the SSSIinclude: (1) the variable reference torque at the denominator; and (2) afixed time period. First, SSSI is a fractional value with both numeratorand denominator changing. The values of both numberator and denominatorat the time have to be known to determine the magnitude of oscillation.Using a moving average torque over a selected time period to calculatethe SSSI may not be an ideal way of representation of the stick slipwhen encountering different formations where the average torque could besignificantly different for the same amount of magnitude (Max Torque-MinTorque) of the oscillation. Second, SSSI uses a sliding time window ofselected time period to determine the maximum and minimum torque values.It may not be efficient to use a fixed time period as the oscillationtime period varies greatly with hole depth or string length. A fixedtime period may have to use an unnecessarily large value to be longenough to cover the cycle.

Thus, there is a need for a method and system that systematicallyestablishes the surface torque oscillation measure.

SUMMARY

In accordance with the teachings of the present disclosure,disadvantages and problems associated with providing a measure ofrotational oscillations are overcome by providing a Surface TorqueOscillation Performance Index (STOPI). STOPI is a fractional value toindicate the magnitude and severity of surface torque fluctuations of adrilling rig, whose numerator is the difference between the calculatedmaximum surface torque value and the minimum one in a dynamicallyspecified time period, and denominator is a configurable constant torquevalue, e.g., top drive rated torque. STOPI is calculated in real time,updated in a preset short time period and reported to an externaldisplay. Therefore, the denominator is a constant reference torque, andthe varying time window corresponds to the fundamental frequency of thedrill string so as to provide a more responsive and current solution.The STOPI provides a good way for a human drilling operator or acomputer controller to visualize whether slip stick oscillations arehappening, and if yes, mitigate via human or computer interventions.

It may be helpful to drilling personnel, particularly when downholemeasurements are not available, to establish an effective measure ofsurface torque oscillations (STOPI). On aspect of the invention is fordrilling personnel to use STOPI to: (1) be aware of how much the surfacetorque oscillates during drilling operation and accordingly adjust therotational speed, weight on bit, and/or rate of penetration to improvethe situation; (2) decide whether to start, stop or modify slip stickmitigation controls, if the drilling rig is equipped with slip stickmitigation controls; and (3) provide a universal standard forperformance comparisons between drilling rigs and/or mitigation controlalgorithms.

Another aspect of the invention is to provide a method for drilling awellbore with a drill rig, the method comprising: rotating a drillstringand a drill bit with a drill rig drive system; applying a weight of thedrillstring on the drill rig; measuring surface torque oscillations ofthe drill string, comprising: determining a fundamental oscillation timeperiod; selecting a time window based on the fundamental oscillationtime period; collecting torque present value data of the drill stringfor the selected time window; determining an amplitude of torqueoscillation from the collected torque present value data; determining areference torque; and dividing the determined amplitude of torqueoscillation by the determined reference torque to obtain a surfacetorque oscillation performance index, whereby the measurement of thesurface torque oscillations of the drill string is a fractional value toindicate the magnitude and severity of surface torque fluctuations ofthe drilling string; and modifying a drilling parameter based on thesurface torque oscillation performance index.

Another aspect of the invention provides a controller of a drill rigsystem having a drillstring and a drill bit, the controller comprising:a rotation receptor that receives a signal corresponding to drillstringrotation speed at the drill rig; a torque receptor that receives asignal corresponding to torque applied to the drillstring at the drillrig; a processor; a non-transitory storage medium; and a set of computerreadable instructions stored in the non-transitory storage medium,wherein when the instructions are executed by the processor allow thecontroller to measure surface torque oscillations of the drill stringby: determining a fundamental oscillation time period; selecting a timewindow based on the fundamental oscillation time period; collectingtorque present value data of the drill string for the selected timewindow; determining an amplitude of torque oscillation from thecollected torque present value data; determining a reference torque; anddividing the determined amplitude of torque oscillation by thedetermined reference torque to obtain a surface torque oscillationperformance index, whereby the measurement of the surface torqueoscillations of the drill string is a fractional value to indicate themagnitude and severity of surface torque fluctuations of the drillingstring.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present embodiments may be acquiredby referring to the following description taken in conjunction with theaccompanying drawings, in which like reference numbers indicate likefeatures.

FIG. 1 illustrates a basic diagram of a drill rig in the process ofdrilling a well wherein there is a control system.

FIG. 2 shows a schematic diagram of a rig control system and otherdrilling rig components.

FIG. 3 is a flow chart of an algorithm for measuring surface torqueoscillations of a drill string.

FIG. 4 is a schematic diagram illustrating levels of control devices ina control architecture.

FIG. 5A is a plot of raw torque values for a drill string simulationmodel.

FIG. 5B is a plot of low pass and band pass filtered torque values forthe drill string simulation model.

FIG. 5C is a double y-axis plot of data for the drill string simulationmodel, wherein the left axis shows STOPI values and the right axis showsthe oscillation magnitudes.

FIG. 6A is a plot of raw torque values for a drill string field test.

FIG. 6B is a plot of low pass and band pass filtered torque values forthe drill string field.

FIG. 6C is a double y-axis plot of data for the drill string field test,wherein the left axis shows STOPI values and the right axis shows theoscillation magnitudes.

DETAILED DESCRIPTION

Preferred embodiments are best understood by reference to FIGS. 1-6Cbelow in view of the following general discussion. The presentdisclosure may be more easily understood in the context of a high leveldescription of certain embodiments.

FIG. 1 is a basic diagram of a drill rig 10 in the process of drilling awell. The drilling rig 10 comprises a drilling rig floor 11 that iselevated and a derrick 12 that extends upwardly from the floor. A crownblock 13 is positioned at the top of the derrick 12 and a travelingblock 14 is suspended therefrom. The traveling block 14 may support atop drive 15. A quill 16 extends from the bottom side of the top drive15 and is used to suspend and/or turn tubular drilling equipment as itis raised/lowered in the wellbore 30. A drillstring 17 is made up to thequill 16, wherein the drillstring 17 comprises a total length ofconnected drill pipe stands, or the like, extending into the well bore30. One or more motors housed in the top drive 15 rotate the drillstring17. A drawworks 18 pays out and reels in drilling line 19 relative tothe crown block 13 and traveling block 14 so as to hoist/lower variousdrilling equipment.

As shown in FIG. 1, a new stand of drillstring 17 has been made up asthe lower portion of the drillstring 17 is suspended from the rig floor11 by a rotary table 20. Slips 21 secure the suspended portion of thedrillstring 17 in the rotary table 20. A bottom hole assembly 22 isfixed to the lower end of the drillstring 17 and includes: a drill bit23 for drilling through a formation 24; a positive displacement motor(PDM) 32; and a measurement while drilling (MWD) module 33.

During the drilling process, drilling mud may be circulated through thewellbore 30 to remove cuttings from around the drill bit 23. A mud pump25 pumps the drilling mud through a discharge line 26, stand pipe 27,and rotary hose 28 to supply drilling mud to the top drive 15. Drillingmud flows from the top drive 15 down through the drillstring 17, whereit exits the drillstring 17 through the drill bit 23. From the drill bit23, the drilling mud flows up through an annulus 31 existing between thewellbore 30 and the drillstring 17 so as to carry cuttings away from thedrill bit 23. A return line 29 allows the drilling mud to flow from thetop of the annulus 31 into a mud pit 33. Of course, the mud pump 25 issupplied drilling mud from the mud pit 33. The drilling mud typicallypasses through a series of shakers, separators, etc. (not shown) toseparate the cuttings from the drilling mud before the mud is circulatedagain by the mud pump 25.

Referring again to FIG. 1, a rig control system 40 may be used todetermine whether slip stick oscillations are occurring. The rig controlsystem 40 may be configured to receive drilling parameter data anddrilling performance data related to operations of the drilling rig 10.The drilling parameter data and drilling performance data may comprisemeasurements monitored by a number of sensors 41 placed about thedrilling rig 10, e.g., a top drive VFD, a torque sub, the drawworks 18,the traveling block 14, the top drive 15, the mud pump 25, and themeasurement while drilling (MWD) module 33 as shown in the illustratedembodiment. The sensors 41 may monitor current, voltage, resistivity,force, position, torque, weight, strain, speed, rotational speed,oscillation or any other measurement related to drilling parameters ordrilling performance, and relevant input may be aggregated as raw sensormeasurements or as scaled engineering values. The rig control system 40may receive drilling parameter data and drilling performance datadirectly from the sensors 41, retrofitted to certain pieces of equipmenton the drilling rig 10, such that the sensors 41 effectively form partof the drilling system. This type of data acquisition may allow forhigher sampling rates to be used for monitoring relevant drillingparameters and drilling performance metrics.

Several components of the drill rig 10 may also comprise controlactuators 42. For example, the drawworks 18 may comprise an actuator 42that allows a controller to control the workings of the drawworks 18.The top drive 15 and mud pump 25 may also have actuators 42. Theactuators 42 allow a supervisory controller to control various aspectsof the drilling process, for example: bit rotation speed, drillstringrotation direction, weight on bit, drilling mud fluid pressure, drillingmud fluid flow rate, drilling mud density, etc.

Referring to FIG. 2, a schematic of a rig control system 40 and otherdrilling rig components is illustrated. The rig control system 40 maycomprise a processor 43 that may receive various inputs, such as thedrilling parameter data and drilling performance data, from sensors 41.In addition, the processor 43 may be operably coupled to a memory 47 anda storage 48 to execute computer executable instructions for carryingout the presently disclosed techniques. These instructions may beencoded in software/hardware programs and modules that may be executedby the processor 43. The computer codes may be stored in any suitablearticle of manufacture that includes at least one tangiblenon-transitory, computer-readable medium (e.g., a hard drive) that atleast collectively stores these instructions or routines, such as thememory 47 or the storage 48. A STOPI module 49 may comprisehardware/software for providing STOPI measurements and determinations.

In some embodiments, the STOPI algorithms may be located in the STOPImodule 49. In other embodiments, the STOPI algorithms may be located onprogrammable logic controllers (PLCs) that control the drilling rigactuators themselves. In some embodiments, the STOPI algorithms may beimplemented in a software layer above the PLC layer. Systems and methodsthat reduce or dampen torsional drillstring vibrations, in particularslip-stick oscillations and torsional drillstring resonances (mitigationslip stick control), may be used with a rig control system as disclosedin US Publication No. 2016/0290046, incorporated herein by reference inits entirety.

Referring to FIG. 3, a block diagram of algorithm 300 according to oneaspect of the present invention is illustrated. The first step ofalgorithm 300 is to collect 310 the torque present value (RawTrqPv),which may be collected from either the VFD related to the top drive 15(not shown in FIG. 1), or a torque sub located between the top drive 15and the drillstring 17 (also not shown in FIG. 1).

Next, the torque present value (RawTrqPv) data is low pass or band passfiltered 320. The cutoff frequencies are predetermined fixed values. Ifthe formations to be drilled for the well are known as fairly constant,low pass filter may apply, otherwise, band pass filter should apply.

Parameters of the drill string length (hole depth) and drill stringproperties are then collected 330 from either local control orsupervisory control at higher level of a hierarchical control network.

The algorithm 300 then calculates 340 the length of the moving window byfirst estimating the fundamental oscillation time period T₁. Anyexisting technique may be used to derive the fundamental time period T₁.For example, one method is to use equations (1)-(3) from A. Kyllinstadand G. W. Halsey, “A Study of Slip/Stick Motion of the Bit,” SPEDrilling Engineering, pgs. 369-373, December 1988, incorporated hereinin its entirety. For a drillstring composed of a drillpipe section oflength L₁ and a uniform drill-collar section of length L₂, a goodapproximation for inertia is

$\begin{matrix}{J = {\frac{\rho\; I_{1}L_{1}}{3} + {\rho\; I_{2}L_{2}}}} & (1)\end{matrix}$where J is the moment of inertia of the drill string, i is density, andI₁ and I₂, respectively, are the cross-sectional polar moments ofdrilling pipe and drill collar. The torsional stiffness K is just

$\begin{matrix}{K = {G\frac{\; I_{1}}{L_{1}}}} & (2)\end{matrix}$where G is the shear modulus of the drillstring material. Where

$\sqrt{\frac{K}{J}}$is the angular eigen frequency, the fundamental time period T₁ iscalculated as

$\begin{matrix}{T_{1} = \frac{2\pi}{\sqrt{\frac{K}{J}}}} & (3)\end{matrix}$Equation (4) establishes the time interval T for the moving window wherea is a safety factor typically set between 1.0 and 2.0 to ensure themoving window covers a full cycle of oscillation at the time. Based onT, the length of moving window can be determined by dividing the controlsystem sampling time ΔT with T. If necessary, the window length isrounded to be an integer.T=αT ₁  (4)

Next, the algorithm 300 sorts 350 the stored torque value array (withthe size of window length) to obtain the largest values p and lowestvalues q, where p and q are integers equal to or larger than 1.

Algorithm 300 then subtracts 360 the average of the q values from theaverage of the p values derived from the sorted torque value array. Thedifference between the two resulting average values provides anamplitude of torsional fluctuations.

The next step in the algorithm 300 is to divide 370 the resultingdifference value (amplitude of torsional fluctuations) by selectedconstant reference torque values. The default setting is a rated torqueof the top drive 15. The reference torque values can also be off-bottomtorque, at-bottom torque, etc. Off-bottom torque is measured by rotatingoff bottom (ROffB), which is where the pipe rotates without any axialmovement, such as rate of penetration or tripping, there is no weight onbit (WOB) or torque on bit (TOB) because the bit is not engaged with theformation. At-bottom torque is measured by rotating on bottom (ROnB),which is where the pipe rotates without any axial movement, such as rateof penetration or tripping, but weight on bit (WOB) and torque on bit(TOB) are present because bit is engaged with the formation. Theselection of reference torque may be dependent on the availability andthe choice of rig personnel. The quotient of the division is a SurfaceTorque Oscillation Performance Index (STOPI).

According to a further step of the algorithm 300, the STOPI valuecalculated from the division step is limited 380 between a configurablemaximum and minimum.

Finally, the algorithm 300 displays 390 the STOPI on an external displaysuch as a HMI or a computer screen. The display update time is generallylonger than ZIT. Therefore, the algorithm 300 may use either a pollingmethod or the average value for the purpose of display.

In addition, the algorithm 300 steps are executed as STOPI calculationis enabled. When the calculation is disabled based on preset conditions(such as bit not at bottom, TD speed setpoint changes, and drillingcontroller off), a ‘null’ value or a high mark integer value would beassigned to STOPI for logging, which also clarifies the ‘disabled’status without misleading.

The STOPI algorithm can be implemented as part of the rig controlsystem. Referring to FIG. 4, control levels are illustrated for adrilling rig control system. A significant difference between each ofthe control levels is to what degree software programs or algorithms maybe edited or reprogrammed after the original software programs oralgorithms have been embedded in the hardware. A further distinctionbetween the levels is the speed of the communications between devices atthe control level.

Level 0 (Field) comprises sensors and actuators for a variety ofdrilling subsystems. Example subsystems include a drilling fluidcirculation system (which may include mud pumps, valves, fluidreconditioning equipment, etc.), a rig control system (which may includehoisting equipment, drillstring rotary mover equipment (such as a topdrive and/or rotary table), a PHM, a catwalk, etc.), a managed pressuredrilling system, a cementing system, a rig walk system, etc. Level 0(Field) may comprise a high speed controller, such as a variablefrequency drive (VFD). Level 0 (Field) hardware devices may beprogrammed with software by the manufacturer and the software may beless suitable for modification unless performed by the manufacturer.

Level 1 (Bottom) comprises direct control devices for directlycontrolling the Level 0 (Field) subsystems. Level 1 (Bottom) directcontrollers can include programmable logic controllers (PLCs),processors, industrial computers, personal computer based controllers,soft PLCs, the like, and/or any example controller configured andoperable to receive sensor data from subsystem sensors and/or transmitcontrol instructions to subsystem equipment. Level 1 (Bottom) processorsmay be, comprise, or be implemented by one or more processors of varioustypes operable in the local application environment, and may include oneor more general purpose processors, special-purpose processors,microprocessors, digital signal processors (DSPs), field-programmablegate arrays (FPGAs), application-specific integrated circuits (ASICs),processors based on a multi-core processor architecture, and/or otherprocessors. More particularly, examples of a processor include one ormore INTEL microprocessors, microcontrollers from the ARM and/or PICOfamilies of microcontrollers, embedded soft/hard processors in one ormore FPGAs, etc. Sensors and various other components may transmitsensor data and/or status data to a direct controller, and controllablecomponents may receive commands from a direct controller to controloperations of the controllable components. One or more aspects disclosedherein may allow communication between direct controllers of differentsubsystems through virtual networks. Sensor data and/or status data maybe communicated through virtual networks and a common data bus betweendirect controllers of different subsystems. Level 1 (Bottom) directcontrollers may be programmed and deployed, but with relativedifficulty. Programmed software may thereafter be configured and edited,but with relative difficulty. Only very rigid computer programming ispossible. A field bus is used to communicate with Level 1 (Bottom)direct controllers via protocols, such as Ethernet CAT, ProfiNET,ProfiBus, Modbus, etc. Processor 43 is an example of a Level 1 (Bottom)device. (See FIG. 2).

Level 2 (Middle) comprises coordinated control devices. These include avariety of computing devices, for example, computers, such as industrialPC, processors, domain controllers, programmable logic controllers(PLCs), industrial computers, personal computers based controllers, softPLCs, the like, and/or any example controller configured and operable toreceive information and data available on a Level 2 network, andtransmit control commands and instructions to direct controllers atLevel 1, which directly control subsystem equipment. Level 2 (Middle)processors may be, comprise, or be implemented by one or more processorsof various types operable in the local application environment, and mayinclude one or more general purpose processors, special-purposeprocessors, microprocessors, digital signal processors (DSPs),field-programmable gate arrays (FPGAs), application-specific integratedcircuits (ASICs), processors based on a multi-core processorarchitecture, and/or other processors. More particularly, examples of aprocessor include one or more INTEL microprocessors, microcontrollersfrom the ARM and/or PICO families of microcontrollers, embeddedsoft/hard processors in one or more FPGAs, etc. Level 2 (Middle)coordinated controllers may be programmed and deployed relatively easilyas high level programming languages, such as C/C++, may be used withsoftware program running in a real time operating system (RTOS). A realtime communication databus is used to communicate with Level 2 (Middle)coordinated controllers via protocols, such as TCP/IP and UDP.

Level 3 (Top) comprises process monitoring devices that do not control,but merely monitor activity and provide information to the controllingdevices at lower levels. Any computing device known to persons of skillin the art may perform Level 3 functions.

A control system implementing the STOPI algorithm may either beimplemented in PLC at Level 1 (Bottom), or in an industrial PC running areal time operating system at Level 2 (Middle), or in a server computeror a virtual machine at any level. Typically, the STOPI algorithm may beimplemented either on PLCs at Level 1 (Bottom) or in a middlewaresoftware layer at Level 2 (Middle). A supervisory controller that mayimplement mitigation slip stick controls may be implemented either in amiddleware software layer at Level 2 (Middle) or at Level 3 (Top).

According to one embodiment of the invention, a surface torqueoscillation performance index (STOPI) is displayed on a display 46 (seeFIG. 2) and a human drilling operator may then use the STOPI to decidewhether to modify a drilling parameter. For example, in response to adisplayed STOPI, the drilling operator may decide whether to modify thedrill string rotational speed, the weight of the drill string on thedrilling rig, and/or the rate of penetration. As a further example, thedrilling operator may decide whether to start, stop or modify a slipstick mitigation control.

Referring to FIGS. 5A through 5C, example data collected from a drillstring simulation model is illustrated for the STOPI algorithm. FIG. 5Ashows raw torque values from the drill string simulation model. FIG. 5Billustrates the low pass and band pass filtered torque values from thedrill string simulation model. FIG. 5C shows a double y-axis plot asleft axis shows STOPI values and right axis shows the oscillationmagnitudes. TD rated torque of 50,000 N·m is used as reference torque(denominator). In this drill string simulation model example, the movingwindow time T is at 5 secs where the oscillation frequency is at about0.21 Hz. A polling method shows a new STOPI value every 500 ms and ΔT=1ms.

Referring to FIGS. 6A through 6C, example data collected from a drillstring field test is illustrated for the STOPI algorithm. FIG. 6A showsraw torque values from the drill string simulation model. FIG. 6Billustrates the low pass and band pass filtered torque values from thedrill string simulation model. FIG. 6C shows a double y-axis plot asleft axis shows STOPI values and right axis shows the oscillationmagnitudes. TD rated torque of 50,000 N·m is used as reference torque(denominator). In this drill string field test example, the movingwindow time T=2 sec and the fundamental frequency is about 0.67 Hz.STOPI values are shown every ΔT=5 ms.

In alternative embodiments, drilling control methods implement acombination of control algorithms based on at least one of thealgorithms disclosed in this specification with any other known controlalgorithm. It is specifically contemplated that control algorithms areimplemented in combination.

Although the disclosed embodiments are described in detail in thepresent disclosure, it should be understood that various changes,substitutions and alterations can be made to the embodiments withoutdeparting from their spirit and scope.

What is claimed is:
 1. A method for drilling a wellbore with a drillrig, the method comprising: rotating a drill string and a drill bit witha drill rig drive system; applying a weight of the drill string on thedrill rig; and measuring surface torque oscillations of the drillstring, comprising: determining a fundamental oscillation time period;selecting a time window based on the fundamental oscillation timeperiod; collecting torque present value data of the drill string for theselected time window; determining an amplitude of torque oscillationfrom the collected torque present value data; determining a referencetorque; and dividing the determined amplitude of torque oscillation bythe determined reference torque to obtain a surface torque oscillationperformance index, whereby the measurement of the surface torqueoscillations of the drill string is a fractional value to indicate themagnitude and severity of surface torque fluctuations of the drillingstring.
 2. The method for drilling a wellbore as claimed in claim 1,further comprising modifying at least one drilling parameter based onthe surface torque oscillation performance index.
 3. The method fordrilling a wellbore as claimed in claim 1, further comprising displayingthe surface torque oscillation performance index on a display.
 4. Themethod for drilling a wellbore as claimed in claim 1, wherein thedetermining a fundamental oscillation time period comprises determiningbased on at least one drill string parameter selected from: drill stringlength, drill string shear modulus, and drill string density.
 5. Themethod for drilling a wellbore as claimed in claim 1, wherein thedetermining the fundamental oscillation time period comprises estimatingbased on at least one drill string parameter selected from: drill stringlength, drill pipe length, drill collar length, string shear modulus,string stiffness, drill string moment of inertia, drill string density,drill pipe polar moment, and drill collar polar moment.
 6. The methodfor drilling a wellbore as claimed in claim 1, wherein determining thereference torque comprises measuring at least one of: an off-bottomtorque, an at-bottom torque, and a top drive rated torque.
 7. The methodfor drilling a wellbore as claimed in claim 1, wherein measuring thesurface torque oscillations of the drill string further comprises:filtering the collected torque present value data; sorting the filteredtorque present value data to obtain a set of large values p and a set ofsmall values q; averaging the set of large values p and averaging theset of small values q; and subtracting the average of the set of smallvalues q from the average of the set of large values p to obtain anamplitude of torsional fluctuations; wherein the dividing collectedtorque present value data by the determined reference torque comprisesdividing the amplitude of torsional fluctuations by the determinedreference torque to obtain the surface torque oscillation performanceindex.
 8. The method for drilling a wellbore as claimed in claim 6,wherein the filtering the collected torque present value data comprisesat least one of: low pass filtering of frequencies at a predeterminedfixed value, and band pass filtering of frequencies at predeterminedfixed values.
 9. The method for drilling a wellbore as claimed in claim2, wherein the modifying at least one drilling parameter comprisesmodifying at least one drilling parameter selected from: drill stringrotational speed, weight of the drill string on the drilling rig, slipstick mitigation control, and rate of penetration.
 10. The method fordrilling a wellbore as claimed in claim 1, further comprising averagingthe surface torque oscillation performance indexes for selectedfundamental oscillation time periods.
 11. The method for drilling awellbore as claimed in claim 1, further comprising polling the surfacetorque oscillation performance indexes for selected fundamentaloscillation time periods.
 12. A controller of a drill rig system havinga drill string and a drill bit, the controller comprising: a rotationreceptor that receives a signal corresponding to drill string rotationspeed at the drill rig; a torque receptor that receives a signalcorresponding to torque applied to the drill string at the drill rig; aprocessor; a non-transitory storage medium; and a set of computerreadable instructions stored in the non-transitory storage medium,wherein when the instructions are executed by the processor allow thecontroller to measure surface torque oscillations of the drill stringby: determining a fundamental oscillation time period; selecting a timewindow based on the fundamental oscillation time period; collectingtorque present value data of the drill string for the selected timewindow; determining an amplitude of torque oscillation from thecollected torque present value data; determining a reference torque; anddividing the determined amplitude of torque oscillation by thedetermined reference torque to obtain a surface torque oscillationperformance index, whereby the measurement of the surface torqueoscillations of the drill string is a fractional value to indicate themagnitude and severity of surface torque fluctuations of the drillingstring.
 13. The controller of a drill rig system as claimed in claim 12,wherein the determining a fundamental oscillation time period comprisesdetermining based on at least one drill string parameter selected from:drill string length, drill string shear modulus, and drill stringdensity.
 14. The controller of a drill rig system as claimed in claim12, wherein the determining the fundamental oscillation time periodcomprises estimating based on at least one drill string parameterselected from: drill string length, drill pipe length, drill collarlength, string shear modulus, string stiffness, drill string moment ofinertia, drill string density, drill pipe polar moment, and drill collarpolar moment.
 15. The controller of a drill rig system as claimed inclaim 12, wherein determining the reference torque comprises measuringat least one of: an off-bottom torque, an at-bottom torque, and a topdrive rated torque.
 16. The controller of a drill rig system as claimedin claim 12, wherein the set of computer readable instructions stored inthe non-transitory storage medium comprise further instructions, whereinwhen the further instructions are executed by the processor allow thecontroller to measure the surface torque oscillations of the drillstring by: filtering the collected torque present value data; sortingthe filtered torque present value data to obtain a set of large values pand a set of small values q; averaging the set of large values p andaveraging the set of small values q; and subtracting the average of theset of small values q from the average of the set of large values p toobtain an amplitude of torsional fluctuations; wherein the dividingcollected torque present value data by the determined reference torquecomprises dividing the amplitude of torsional fluctuations by thedetermined reference torque to obtain the surface torque oscillationperformance index.
 17. The controller of a drill rig system as claimedin claim 16, wherein the filtering the collected torque present valuedata comprises at least one of: low pass filtering of frequencies at apredetermined fixed value, and band pass filtering of frequencies atpredetermined fixed values.
 18. The controller of a drill rig system asclaimed in claim 12, wherein the set of computer readable instructionsstored in the non-transitory storage medium comprise furtherinstructions, wherein when the further instructions are executed by theprocessor allow the controller to modify at least one drilling parameterselected from: drill string rotational speed, weight of the drill stringon the drilling rig, slip stick mitigation control, and rate ofpenetration.
 19. The controller of a drill rig system as claimed inclaim 12, wherein the set of computer readable instructions stored inthe non-transitory storage medium comprise further instructions, whereinwhen the further instructions are executed by the processor allow thecontroller to display the surface torque oscillation performance index.20. The controller of a drill rig system as claimed in claim 12, whereinthe set of computer readable instructions stored in the non-transitorystorage medium comprise further instructions, wherein when the furtherinstructions are executed by the processor allow the controller toaverage the surface torque oscillation performance indexes for selectedfundamental oscillation time periods.
 21. The controller of a drill rigsystem as claimed in claim 12, wherein the set of computer readableinstructions stored in the non-transitory storage medium comprisefurther instructions, wherein when the further instructions are executedby the processor allow the controller to poll the surface torqueoscillation performance indexes for selected fundamental oscillationtime periods.
 22. The controller of a drill rig system as claimed inclaim 12, wherein the non-transitory storage medium is implemented in acontrol device selected from PLC at Level 1 (Bottom), and an industrialPC running middleware software at Level 2 (Middle).